Methods and compositions for treating subterranean formations using sulfonated gelling agent polymers

ABSTRACT

Treating fluids comprising sulfonated gelling agent polymers, and methods of use in treating subterranean formations, are provided. The treating fluids comprise water and one or more sulfonated gelling agent polymers. In one embodiment, the methods comprise providing a treating fluid that comprises water and one or more sulfonated gelling agent polymer; and introducing the treating fluid into a subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of copending U.S. patentapplication Ser. No. 10/670,410, entitled “Methods and Compositions forTreating Subterranean Formations Using High Ionic Strength Gelling AgentPolymers,” filed on Sep. 24, 2003, the entirety of which is hereinincorporated by reference.

BACKGROUND OF THE INVENTION

The present invention relates to treating fluids comprising sulfonatedgelling agent polymers, and methods of use in treating subterraneanformations.

Viscous treating fluids are used in a variety of operations andtreatments in oil and gas wells. Such operations and treatments includeforming gravel packs in well bores, fracturing producing zones,performing permeability control treatments and the like. As used herein,the term “treatment,” or “treating,” refers to any subterraneanoperation that uses a fluid in conjunction with a desired functionand/or for a desired purpose. The terms “treatment,” and “treating,” asused herein, do not imply any particular action by the fluid or anyparticular component thereof.

Hydrocarbon producing wells are often stimulated by hydraulic fracturingtreatments. In hydraulic fracturing, a viscous fracturing fluid, whichalso functions as a carrier fluid, is pumped into a subterraneanformation to be fractured at a rate and pressure such that one or morefractures are formed or enhanced in the formation. “Enhancing” one ormore fractures in a subterranean formation, as that term is used herein,is defined to include the extension or enlargement of one or morenatural or previously created fractures in the subterranean formation.Proppant particles, e.g., graded sand, for propping the fractures openare suspended in the fracturing fluid and are deposited in the fractureswhen the fracturing fluid viscosity is reduced. The fracturing fluidviscosity is reduced by including a delayed viscosity breaker in thefracturing fluid that causes it to revert to a thin fluid. The proppantparticles deposited in the fractures function to prevent the fracturesfrom closing so that conductive channels are formed through whichproduced hydrocarbons can readily flow.

Aqueous treating fluids are generally viscosified by mixing a hydratablepolysaccharide gelling agent polymer with water. For example, guar gumand its derivatives are often used to viscosity aqueous fracturingfluids. Guar gum is a random coil polymer that can be readilycrosslinked with various cross-linking agents, e.g., metal ions. Oncecrosslinked, guar and guar derivatives can form highly viscoelastic gelsthat approach near zero suspended particle settling rates.

Often increasing the effectiveness of gelling agent polymers isdesirable, and this has been achieved to a significant degree bygrafting ionic groups, for example carboxyl groups, onto the gellingagent polymer chain. Since like charges tend to repel each other, thecarboxyl groups are thought to force the flexible coiled polymer tobecome more linear. Maximizing the linearity is thought to result in anenlarged radius of gyration, which in turn is thought to result in alesser amount of gelling agent being required to generate a gelledtreating fluid.

One problem with using gelling agent polymers comprising ionic groups isthat the viscosity-increasing effect of carboxyl groups is thought to begreatly reduced as the pH of the fluid drops below 7. This is thought tobe due to the fact that the carboxylate ions are salts of weak acids andtend to hydrolyze. In addition, the solubility of anionic groups inwater containing multivalent metal ions such as calcium and magnesium islow, making gelling agent polymers containing anionic groups, e.g.,carboxyl groups, generally less soluble in hard water. Thus, anionicgroups is thought to render the viscosity of a treating fluid thatcomprises conventional gelling agent polymers sensitive to ionicstrength, whereby the viscosity of the treating fluid that comprises oneor more water soluble salts is thought to be much less than theviscosity in fresh water. This sensitivity to ionic strength may beundesirable since the aqueous liquids used in well treating fluids oftencontain salts, for example, when the treating fluid comprises saltwater,brines, seawater, produced water (e.g., naturally-occurring water foundin a subterranean formation), or flowback water (e.g., water that waspreviously placed in a subterranean formation, for example, in thecourse of performing another operation), when the subterranean formationcomprises salts that dissolve in the treating fluid, and/or as anadditive to inhibit swelling of formation clays.

SUMMARY OF THE INVENTION

The present invention relates to treating fluids comprising sulfonatedgelling agent polymers, and methods of use in treating subterraneanformations.

In one embodiment, the present invention provides a method of treating asubterranean formation penetrated by a well bore comprising: providing atreating fluid that comprises water and one or more sulfonated gellingagent polymers; and introducing the treating fluid into the subterraneanformation.

In another embodiment, the present invention provides a method offorming one or more fractures in a subterranean formation penetrated bya well bore comprising: providing a treating fluid that comprises waterand one or more sulfonated gelling agent polymers; and introducing thetreating fluid into the subterranean formation at a rate and pressuresufficient to create or enhance one or more fractures therein.

In another embodiment, the present invention provides a high ionicstrength treating fluid composition for treating a subterraneanformation comprising water and one or more sulfonated gelling agentpolymers.

The features and advantages of the present invention will be apparent tothose skilled in the art. While numerous changes may be made by thoseskilled in the art, such changes are within the spirit of the invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to treating fluids comprising sulfonatedgelling agent polymers, and methods of use in treating subterraneanformations.

The treating fluids of the present invention generally comprise waterand one or more sulfonated gelling agent polymers. The methods of thepresent invention for treating subterranean formations penetrated bywell bores generally comprise providing a treating fluid that compriseswater and one or more sulfonated gelling agent polymers; and introducingthe treating fluid into a subterranean formation. The treating fluids ofthe present invention may exhibit, among other things, decreasedsensitivity to low pH, high ionic strength conditions, and/or hardwater. This may, inter alia, provide increased viscosity to the treatingfluids of the present invention.

In certain embodiments, the treating fluids used in the presentinvention may comprise a “high ionic strength treating fluid,” whichrefers to a fluid (or portion thereof) that comprises a substantialamount of water-soluble salts. In certain embodiments, a high ionicstrength treating fluid may comprise one or more water soluble salts ina concentration of greater than about 1% by weight of the treatingfluid. In certain embodiments, a high ionic strength treating fluid maycomprise one or more water soluble salts in a concentration of greaterthan about 8% by weight of the treating fluid. In certain embodiments, ahigh ionic strength treating fluid may comprise one or more watersoluble salts in a concentration of greater than about 20% by weight ofthe treating fluid.

The water utilized in the treating fluids of this invention may comprisefresh water, salt water (e.g., brines or seawater), produced water,flowback water, or a combination thereof. The term “produced water” isdefined herein to include any naturally-occurring water found in asubterranean formation. The term flowback water is defined herein toinclude any water (or treating fluid comprising water) that waspreviously placed in a subterranean formation, for example, in thecourse of performing another operation.

The one or more sulfonated gelling agent polymers used in the presentinvention may include, but are not limited to the following: sulfonatedbiopolymers such as xanthan, scleroglucan and succinoglycan; sulfonatedsynthetic polymers such as sulfonated polyvinyl alcohols, sulfonatedpolyacrylamides, and sulfonated polyacrylates; sulfonatedacrylamide/acrylic acid copolymers; sulfonated polysaccharides;sulfonated polysaccharide derivatives; and derivatives thereof. The term“derivative,” as used herein, includes any compound that is made fromone of the listed compounds, for example, by replacing one atom in thelisted compound with another atom or group of atoms, rearranging two ormore atoms in the listed compound, ionizing one of the listed compounds,or creating a salt of one of the listed compounds. Sulfonatedpolysaccharides include, but are not limited to, sulfonatedgalactomannan gums such as guar gum, gum arabic, gum ghatti, gum karaya,tamarind gum, locust bean gum, sulfonated cellulose derivatives, andderivatives thereof. Examples of suitable sulfonated galactomannan gumpolymers include sulfonated guar, sulfonated hydroxypropylguar,sulfonated carboxymethylhydroxyethyl guar, sulfonated carboxymethylguar,and derivatives thereof. Examples of suitable sulfonated cellulosederivatives include sulfonated carboxymethylcellulose, sulfonatedcarboxymethylhydroxyethylcellulose, sulfonated hydroxyethylcellulose,sulfonated methylhydroxypropylcellulose, sulfonated methylcellulose,sulfonated ethylcellulose, sulfonated propylcellulose, sulfonatedethylcarboxymethylcellulose, sulfonated methylethylcellulose, sulfonatedhydroxypropylmethylcellulose, and derivatives thereof. In certainembodiments, the one or more sulfonated gelling agent polymers maycomprise a combination of different sulfonated gelling agent polymers.

In certain embodiments of the present invention, the one or moresulfonated gelling agent polymers may be present in the treating fluidin an amount in the range of from about 20 lbs to about 60 lbs ofpolymer per 1000 gal of the treating fluid. In certain embodiments, theone or more sulfonated gelling agent polymers may be present in thetreating fluid in an amount in the range of from about 30 lbs to about45 lbs per 1000 gal of the treating fluid. Methods of preparing theaqueous treating fluids of the present invention will be recognized bythose skilled in the art, with the benefit of this disclosure.

A crosslinking agent optionally may be added, among other purposes, tofurther enhance the viscosity of the treating fluid. The term“crosslinking agent” is defined herein to include any molecule, atom, orion that is capable of forming one or more crosslinks between moleculesof a polymer and/or between one or more atoms in a single molecule of apolymer. The crosslinking agent may comprise a borate, a metal ion, orsimilar component that is capable of crosslinking at least two moleculesof the sulfonated gelling agent polymer(s). Examples of suitablecrosslinking agents that can be utilized include, but are not limited tothe following: boron compounds such as boric acid, disodium octaboratetetrahydrate, sodium diborate and pentaborates; ulexite; colemanite;compounds that can supply zirconium IV ions such as zirconium lactate,zirconium lactate triethanolamine, zirconium carbonate, zirconiumacetylacetonate and zirconium diisopropylamine lactate; compounds thatcan supply titanium IV ions such as titanium ammonium lactate, titaniumtriethanolamine and titanium acetylacetonate; aluminum compounds such asaluminum lactate and aluminum citrate; and compounds that can supplyantimony ions. In certain embodiments of the present invention, thecrosslinking agent may be formulated to remain inactive until it is“activated” by, among other things, certain conditions in the fluid(e.g., pH, temperature, etc.) and/or interaction with some othersubstance. In some embodiments, the crosslinking agent may be delayed byencapsulation with a coating (e.g., a porous coating through which thecrosslinking agent may diffuse slowly, or a degradable coating thatdegrades downhole) that delays the release of the crosslinking agentuntil a desired time or place. The choice of a particular crosslinkingagent will be governed by several considerations that will be recognizedby one skilled in the art, including but not limited to the following:the type of gelling agent included, the molecular weight of the gellingagent(s), the conditions in the subterranean formation being treated,the safety handling requirements, the pH of the treating fluid,temperature, and/or the desired delay for the crosslinking agent tocrosslink the gelling agent molecules.

In certain embodiments, a crosslinking agent may be included in thetreating fluid in an amount in the range of from about 2 lbs to about 40lbs per 1000 gal of the treating fluid. In certain embodiments, acrosslinking agent may be included in the treating fluid in an amount inthe range of from about 4 lbs to about 12 lbs per 1000 gal of thetreating fluid.

The treating fluids of the present invention optionally may compriseparticulates, such as proppant particulates or gravel particulates.Particulates suitable for use in the present invention may comprise anymaterial suitable for use in subterranean operations. Suitable materialsfor these particulates include, but are not limited to, sand, bauxite,ceramic materials, glass materials, polymer materials, Teflon®materials, nut shell pieces, cured resinous particulates comprising nutshell pieces, seed shell pieces, cured resinous particulates comprisingseed shell pieces, fruit pit pieces, cured resinous particulatescomprising fruit pit pieces, wood, composite particulates, andcombinations thereof. Suitable composite particulates may comprise abinder and a filler material wherein suitable filler materials includesilica, alumina, fumed carbon, carbon black, graphite, mica, titaniumdioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron,fly ash, hollow glass microspheres, solid glass, and combinationsthereof. The mean particulate size generally may range from about 2 meshto about 400 mesh on the U.S. Sieve Series; however, in certaincircumstances, other mean particulate sizes may be desired and will beentirely suitable for practice of the present invention. In particularembodiments, preferred mean particulates size distribution ranges areone or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or50/70 mesh. It should be understood that the term “particulate,” as usedin this disclosure, includes all known shapes of materials, includingsubstantially spherical materials, fibrous materials, polygonalmaterials (such as cubic materials), and mixtures thereof. Moreover,fibrous materials, that may or may not be used to bear the pressure of aclosed fracture, may be included in certain embodiments of the presentinvention. In certain embodiments, the particulates included in thetreating fluids of the present invention may be coated with any suitableresin or tackifying agent known to those of ordinary skill in the art.In certain embodiments, the particulates may be present in the treatingfluids of the present invention in an amount in the range of from about0.5 pounds per gallon (“ppg”) to about 30 ppg by volume of the treatingfluid.

The treating fluids of the present invention also may include internalgel breakers such as enzyme, oxidizing, acid buffer, or delayed gelbreakers. The gel breakers may cause the treating fluids of the presentinvention to revert to thin fluids that can be produced back to thesurface, for example, after they have been used to place proppantparticles in subterranean fractures. In some embodiments, the gelbreaker may be formulated to remain inactive until it is “activated” by,among other things, certain conditions in the fluid (e.g., pH,temperature, etc.) and/or interaction with some other substance. In someembodiments, the gel breaker may be delayed by encapsulation with acoating (e.g., a porous coatings through which the breaker may diffuseslowly, or a degradable coating that degrades downhole.) That delays therelease of the gel breaker. In certain embodiments, the gel breaker usedmay be present in the treating fluid in an amount in the range of fromabout 0.0001% to about 200% by weight of the gelling agent. One ofordinary skill in the art, with the benefit of this disclosure, willrecognize the type and amount of a gel breaker to include in certaintreating fluids of the present invention based on, among other factors,the desired amount of delay time before the gel breaks, the type ofgelling agents used, the temperature conditions of a particularapplication, the desired rate and degree of viscosity reduction, and/orthe pH of the treating fluid.

The treating fluids of the present invention optionally may include oneor more of a variety of well-known additives, such as gel stabilizers,fluid loss control additives, scale inhibitors, corrosion inhibitors,catalysts, clay stabilizers, biocides, bactericides, friction reducers,gases, foaming agents, surfactants, iron control agents, solubilizers,pH adjusting agents (e.g., buffers), and the like. For example, in someembodiments, it may be desired to foam a treating fluid of the presentinvention using a gas, such as air, nitrogen, or carbon dioxide. Thoseof ordinary skill in the art, with the benefit of this disclosure, willbe able to determine the appropriate additives for a particularapplication.

The treating fluids of the present invention may be prepared by anymethod suitable for a given application. For example, certain componentsof the treating fluid of the present invention (e.g., crosslinkablepolymers, biopolymers, etc.) may be provided in a pre-blended powder,which may be combined with the aqueous base fluid at a subsequent time.In preparing the treating fluids of the present invention, the pH of theaqueous base fluid may be adjusted, among other purposes, to facilitatethe hydration of the gelling agent. The pH range in which the gellingagent will readily hydrate may depend upon a variety of factors (e.g.,the components of the gelling agent, etc.) that will be recognized byone skilled in the art. This adjustment of pH may occur prior to,during, or subsequent to the addition of the gelling agent and/or othercomponents of the treating fluids of the present invention. For example,the treating fluids of the present invention may comprise an ester thatreleases an acid once placed downhole that is capable of, inter alia,reducing the pH and/or viscosity of the treating fluid. After thepre-blended powders and the aqueous base fluid have been combined,crosslinking agents and/or other suitable additives may be added priorto introduction into the well bore. Those of ordinary skill in the art,with the benefit of this disclosure will be able to determine othersuitable methods for the preparation of the treating fluids of thepresent invention.

The treating fluids of the present invention may be used in anysubterranean operation wherein a fluid may be used. Suitablesubterranean operations may include, but are not limited to, drillingoperations, hydraulic fracturing treatments, sand control treatments(e.g., gravel packing), acidizing treatments (e.g., matrix acidizing orfracture acidizing), “frac-pack” treatments, well bore clean-outtreatments, and other suitable operations where a treating fluid of thepresent invention may be useful.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention.

EXAMPLES Example 1

To demonstrate the stability of sulfonated gelling agent polymers topotassium chloride, the viscosity of a 0.5% solution of sulfonated guarpolymer was compared to that of a 0.5% solutions of carboxymethyl guarat 75° F. Viscosity measurements were made with increasing additions ofpotassium chloride.

The results are shown in Table 1 below. The viscosity of carboxymethylguar decreases significantly with initial additions of potassiumchloride. The sulfonated polymer basically maintains its viscosity.TABLE 1 Viscosity After KCl Addition Viscosity, cP % KCl CMG* SULF* 026.34 28.7 0.25 20.29 — 0.5 20.15 — 1 19.08 27.3 2 18.75 26.3 3 18.8225.5 4 18.69 24.8 5 18.49 24.2 6 18.19 23.6 7 18.14 23.2 8 17.89 22.9 917.68 22.3 10 17.65 22.2 11 17.90 22.5 12 17.61 22.6*CMG = Carboxymethyl guar*SULF = Sulfonated guar

Example 2

To demonstrate the superior stability of sulfonated gelling agentpolymers in the presence of divalent cations, a 0.5% solution ofsulfonated guar polymer was compared to that of a 0.5% solution ofcarboxymethyl guar. Viscosity measurements were made at 75° F. withincreasing additions of calcium chloride.

The results are shown in Table 2 below. The viscosity of carboxymethylguar decreases significantly with initial additions of calcium chloride.The sulfonated polymer basically maintains its viscosity. TABLE 2Viscosity After CaCl₂ Addition Viscosity, cP % CaCl₂ CMG* SULF* 0 24.428.9 0.125 19.9 28.7 0.25 19.5 28.9 0.50 19.8 28.9 0.75 — 28.9 1.0 20.628.9 2.0 21.7 28.9 3.0 22.2 29.1 4.0 22.7 29.1 5.0 23 29.0 6.0 23 29.110 26 30.6*CMG = Carboxymethyl guar*SULF = Sulfonated guar

Example 3

The thermal stability of a carboxymethyl guar treating solution wascompared to a sulfonated guar polymer treating solution of thisinvention. The polymer solutions were prepared at a concentration of 0.5weight percent in deionized water. In two of the tests, a gelstabilizing agent comprised of sodium thiosulfate, was added asindicated in Table 3 below. The polymer solutions were hydrated at pH 7and the viscosities were measured at 75° F. The solutions were spargedwith nitrogen and heated in a pressure vessel under 100 psi to 300° F.for 4 hours. The solutions were then cooled to 75° F. and theviscosities were measured again.

As shown in Table 3, the solutions of sulfonated guar polymer hadsuperior thermal stability compare to the carboxymethyl guar. TABLE 3Effect of Time and Temperature on Viscosity Gel Gelling StabilizingFinal Agent Agent lb/1000 Initial Viscosity Viscosity % of InitialSample Polymer gal cP @ 75 F. cP @ 75 F.* Viscosity* 1 CarboxymethylguarNone 39.02 2.2 5.6 2 Carboxymethylguar 20 36.37 5.65 15.5 3 SulfonatedGuar None 40.48 4.4 10.9 4 Sulfonated Guar 20 38.63 10.74 27.8*after 4 hours at 300° F.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Whilenumerous changes may be made by those skilled in the art, such changesare encompassed within the spirit of this invention as defined by theappended claims. The particular embodiments disclosed above areillustrative only, as the present invention may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present invention. In particular, every range ofvalues (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theappended claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee.

1. A method of treating a subterranean formation penetrated by a wellbore comprising: providing a treating fluid that comprises water and oneor more sulfonated gelling agent polymers; and introducing the treatingfluid into the subterranean formation.
 2. The method of claim 1 whereinthe treating fluid is a high ionic strength treating fluid.
 3. Themethod of claim 2 wherein the high ionic strength treating fluidcomprises one or more water soluble salts in a concentration of greaterthan about 1% by weight of the treating fluid.
 4. The method of claim 2wherein the high ionic strength treating fluid comprises one or morewater soluble salts in a concentration of greater than about 8% byweight of the treating fluid.
 5. The method of claim 1 wherein the wateris selected from the group consisting of produced water, flowback water,and combinations thereof.
 6. The method of claim 1 wherein the one ormore sulfonated gelling agent polymers are selected from the groupconsisting of sulfonated biopolymers, sulfonated synthetic polymers,sulfonated polysaccharides, sulfonated polysaccharide derivatives, andcombinations thereof.
 7. The method of claim 1 wherein the one or moresulfonated gelling agent polymers comprise a sulfonated biopolymerselected from the group consisting of sulfonated xanthan, sulfonatedscleroglucan, sulfonated succinoglycan, and combinations thereof.
 8. Themethod of claim 1 wherein the one or more sulfonated gelling agentpolymers comprise a sulfonated synthetic polymer selected from the groupconsisting of sulfonated polyvinyl alcohol, sulfonated polyacrylamide,sulfonated polyacrylate, sulfonated polyacrylamide/acrylic acidcopolymers, and combinations thereof.
 9. The method of claim 1 whereinthe one or more sulfonated gelling agent polymers comprise a sulfonatedpolysaccharide selected from the group consisting of sulfonatedgalactomannan gums, sulfonated cellulose, and combinations thereof. 10.The method of claim 1 wherein the one or more sulfonated gelling agentpolymers comprise a sulfonated galactomannan gum selected from the groupconsisting of sulfonated guar gum, sulfonated gum arabic, sulfonated gumghatti, sulfonated gum karaya, sulfonated tamarind gum, sulfonatedlocust bean gum, and combinations thereof.
 11. The method of claim 1wherein the one or more sulfonated gelling agent polymers comprise asulfonated polysaccharide derivative selected from the group consistingof sulfonated carboxyalkyl derivatives of guar, sulfonated hydroxyalkylderivatives of guar, sulfonated cellulose derivatives, and combinationsthereof.
 12. The method of claim 1 wherein the one or more sulfonatedgelling agent polymers comprise a sulfonated cellulose derivativeselected from the group consisting of sulfonated carboxymethylcellulose,sulfonated carboxymethylhydroxyethylcellulose, sulfonatedhydroxyethylcellulose, sulfonated methylhydroxypropylcellulose,sulfonated methylcellulose, sulfonated ethylcellulose, sulfonatedpropylcellulose, sulfonated ethylcarboxymethylcellulose, sulfonatedmethylethylcellulose, sulfonated hydroxypropylmethylcellulose, andcombinations thereof.
 13. The method of claim 1 wherein the one or moresulfonated gelling agent polymers comprise sulfonated guar.
 14. Themethod of claim 1 wherein the one or more sulfonated gelling agentpolymers are present in the aqueous treating fluid composition in anamount in the range of from about 20 lbs to about 60 lbs per 1000 gal ofthe aqueous treating fluid composition.
 15. The method of claim 1wherein the treating fluid further comprises a crosslinking agent. 16.The method of claim 15 wherein the crosslinking agent is present in thetreating fluid in an amount in the range of from about 2 lbs to about 40lbs per 1000 gal of the treating fluid.
 17. A method of forming one ormore fractures in a subterranean formation penetrated by a well borecomprising: providing a treating fluid that comprises water and one ormore sulfonated gelling agent polymers; and introducing the treatingfluid into the subterranean formation at a rate and pressure sufficientto create or enhance one or more fractures therein.
 18. The method ofclaim 17 wherein the treating fluid is a high ionic strength treatingcomposition.
 19. A high ionic strength treating fluid composition fortreating a subterranean formation comprising water and one or moresulfonated gelling agent polymers.
 20. The high ionic strength treatingfluid composition of claim 19, wherein the composition comprises one ormore water soluble salts in a concentration of greater than about 8% byweight of the treating fluid composition.